Risers are used in offshore drilling applications to provide a means of returning the drilling fluid and any additional solids and/or fluids from the borehole back to surface.
Riser sections are sturdily built as they have to withstand significant loads imposed by the weights they have to carry and the environmental loads they have to withstand when in operation. As such they have an inherent internal pressure capacity. However, this capacity is not currently exploited to the maximum possible. Many systems have been proposed to vary the density of fluid in the riser but none have provided a universally applicable and easily deliverable system for varying types of drilling modes. They all require some specific modification of the main components of a floating drilling installation with the result that they are custom solutions with a narrow range of application due to the costs and design limitations. For example, different drilling systems are required for different drilling modes such as managed pressure drilling, dual density or dual gradient drilling, partial riser level drilling, and underbalanced drilling.
An example of the most common current practice is illustrated by FIG. 1, which is proposed in U.S. Pat. No. 4,626,135 assigned on its face to the Hydril Company. To compensate for movement of the floating drilling installation a slip joint SJ (telescopic joint) is introduced. This slip joint consist of an inner barrel IB and an outer barrel OB that move relative to each other, thus allowing the floating structure S to move without breaking the riser R between the fixed point well W and the moving point D, which is the diverter where the top of the riser returns the drilling fluid. A ball joint BJ (also called and designed as a flex-joint) provides for some angular displacement of the riser from vertical. The conventional method sees any pressure in the riser R due to flow of pressurized fluids from well W as an uncontrolled event (kick) that is controlled by closing the BOP (Blow Out Preventer) either by rams around the tubulars, or by blind rams if no tubulars present or by shear rams capable of cutting the tubulars. It is possible for the kick to enter the riser R and then it is controlled by closing the diverter D (with or without tubulars present) and diverting the undesired flow through diverter lines DL. In the U.S. Pat. No. 4,626,135 patent Hydril introduces the concept of an annular blow out preventer used as a gas handler to divert the flow of gas from a well control incident. This allows diversion of gas by closing around the tubulars in hole, but not when drilling, i.e., rotating the tubular.
In FIG. 1 the seals between the outer barrel OB and inner barrel IB are subjected to much movement due to wave motion and this has led to a limitation of the pressure sealing capacity available for the riser. In fact the American Petroleum Institute (API) has established pressure ratings for such seals in its specification 16F, which calls for testing to 200 psi. In practice the common upper limit for most designs is 500 psi. There are some modifications that can be made as shown in U.S. Patent Application No. US2003/0111799A1 assigned on the face to the Cooper Cameron Corporation which envisions a working rating to 750 psi. In practice the limitation on the slip joint seal has also led to an accepted standard in the industry of the diverter D, ball joint BJ (also sometimes replaced by a unit called flex-joint) and other parts of the system like the valves on the diverter line DL having an industry wide rating of 500 psi working pressure. The outer barrel OB of the slip joint SJ (telescopic joint) also acts as the attachment point for the tension system that serves to keep the riser R in tension to prevent it from buckling. This means that a leak on the slip joint SJ seals involves significant down time in having to lift the whole riser from the subsea BOP (Blow Out Preventer) and servicing the slip joint SJ. In practice it has meant that no floating drilling installation service provider or operating company has been willing to take the risk to continuously operate with any pressure in the riser for the conventional system as depicted again in FIG. 3a. 
U.S. patent application Ser. No. US2005/0061546 and U.S. Pat. No. 6,913,092 assigned on their face to Weatherford/Lamb Inc. have addressed this problem by proposing the locking closed of the slip joint SJ, which means locking the inner barrel to the outer barrel, thus eliminating movement across the slip joint seal. The riser R is then effectively disconnected from the ball joint BJ and diverter D as shown in FIG. 2. The riser is closed by adding a rotating blowout preventer BOP on top of the locked closed slip joint SJ. This effectively decouples the riser R from any fixed point below the rotary table RT. This method has been used and allowed operations with a limit of 500 psi, the weak point still being the slip joint seals. However decoupling the riser R means that it is only held by the tensioner system T1 and T2. This means that the top of the riser is no longer self centralizing. This causes the top of the Rotating Control Device RCD to be off center as a result of the ocean currents, wind patterns, or movement of the floating structure. This introduces significant wear on the sealing element(s) of the RCD, which is detrimental to the pressure integrity of that system.
Also, the design introduces a significant safety hazard as now substantial amounts of easily damaged hydraulic hoses used in the operation of the RCD, as well as pressurized hose(s) DL and safety conduit SC, are introduced to the vicinity of the riser tensioner wires depicted as coming from the slip joint SJ to the sheaves at the bottom of the tensioners T1, T2. These wires are under substantial loads in the order of 50 to 100 tons each and can easily cut through softer rubber goods (hoses). The U.S. Pat. No. 6,913,092 patent suggests the use of steel pipes, but this is extremely difficult to achieve in practice. Also, the installation and operation involves personnel around the RCD, a hazardous area with the relative movement of the floating structure to the top of the riser. All of the equipment does not fit through the rotary table RT and diverter housing D, thus making installation complex and hazardous. Thus the use of this invention has been limited to operations in benign sea areas with little current, wave motion, and wind loads.
A summary of the evolution for the art for drilling with pressure in the riser is shown in FIGS. 3a to 3c. FIG. 3a shows the conventional floating drilling installation set-up. This consists typically of an 18¾ inch subsea BOP stack, with a LMRP (Lower Marine Riser Package) added to allow disconnection and prevent loss of fluids from the riser, a 21 inch riser, and a top configuration identical in principle to the U.S. Pat. No. 4,626,135 patent. This is the configuration used by more than 80% of today's floating drilling installations. In order to reduce costs the industry moved towards the idea of using a SBOP (Surface Blow Out Preventer), with a floating drilling installation, U.S. Pat. No. 6,273,193 as illustrated in FIG. 4, where the 21 inch riser is replaced with a smaller high pressure riser capped with a SBOP package similar to a non-floating drilling installation set-up as illustrated in FIG. 3b. This design evolved to dispensing completely with the subsea BOP, thus removing the need for choke, kill, and other lines from the sea floor back to the floating drilling installation and over 160 wells were drilled like this in benign ocean areas. In attempting to take the concept of a SBOP and high pressure riser further into more environmentally harsh areas a subsea component for disconnection (as marketed by the Cameron corporation as the ESG system) and securing the well in case of emergency was re-introduced, but not as a full subsea BOP. This is shown in FIG. 3c with another evolution of running the SBOP below the water line and tensioners above to enable for heave on floating drilling installations with limited clearance. The method of U.S. Pat. No. 6,913,092 is shown in FIG. 3d for comparison. In trying to plan for substantially higher pressures as experienced in underbalanced drilling where the formation being drilled is allowed to flow with the drilling fluid to surface, the industry has favored designs utilizing an inner riser run within the typical 21 inch marine riser as described in U.S. Pat. App. 2006/0021755 A1. This requires a SBOP as shown in FIG. 3e. The drawback of all these systems is that they require substantial modification of the floating drilling installation to enable the use of SBOP (Surface Blow Out Preventers) and the majority are limited to benign sea and weather conditions. Thus they are not widely implemented as it requires the floating drilling installation to undergo modifications in a shipyard.
Methods and systems as shown in U.S. Pat. Nos. 6,230,824 B1 and 6,138,774 attempt to disperse totally with the marine riser. Methods and systems described in U.S. Pat. No. 6,450,262, U.S. Pat. No. 6,470,975, and U.S. Pat. App. 2006/0102387A1 envisions setting a RCD device on top of the subsea BOP to divert pressure from the marine riser as does U.S. Pat. No. 7,080,685 B2. All of these patents are not widely applied as they involve substantial modifications and additions to existing equipment to be successfully applied. FIG. 5 shows this as depicted in U.S. Pat. No. 6,470,975. The problem with the foregoing systems that utilize a high pressure riser or a riserless setup is that one of the primary means of delivering additional fluids to the seafloor, namely the booster line BL that is a typical part of the conventional system as depicted in FIG. 3a is removed. The booster line BL is also indicated in FIG. 1 and FIG. 2. So the systems shown in FIGS. 3b and 3c, while providing some advantages, take away one of the primary means of delivering fluid into the riser. Also the typical booster line BL is tied in to the base of the riser which means that the delivery point is fixed.
There is also an evolution in the industry to move from conventional drilling to closed system drilling. These types of closed systems are described in U.S. Pat. Nos. 6,904,981 and 7,044,237 and require the closure and by consequence the trapping of pressure inside the marine riser for floating drilling installations. This is schematically depicted in FIG. 6b, with FIG. 6a depicting the conventional system of FIG. 3a for comparison. Also the introduction of a method and system to allow continuous circulation as described in U.S. Pat. No. 6,739,397 allows a drilling circulation system to be operated at constant pressure as the pumps do not have to be switched off when making or breaking a tubular connection. This allows the possibility of drilling with a constant pressure downhole, which can be controlled by a pressurized closed drilling system. The industry calls this Managed Pressure Drilling. With the conventional method of FIG. 3a, no continuous pressure can be kept in the riser. With the method of the U.S. Pat. No. 6,913,092 patent in FIG. 3d the envelope has been taken to 500 psi, however with the substantial addition of hazards and many drawbacks. It is possible to increase the envelope by the methods shown in FIGS. 3b, 3c and 3e. However the addition of a SBOP (Surface BOP) to a floating drilling installation is not a normal design consideration and involves substantial modification usually involving a shipyard with the consequence of operational downtime as well as substantial costs involved, as already mentioned earlier. The system and method of this invention will enable all the systems shown in FIGS. 3a to 3g to be pressurized and to have the ability to inject fluids at any point into the riser. Furthermore any modification that lessens the normal operating envelope (i.e. weather, current, wave and storm survival capability) of the floating drilling installation leads to a limitation in use of that system. The systems shown in FIGS. 3b, 3d, 3e, and 3g all lessen this operating envelope, which is a major reason why these systems have not been applied in harsher environmental conditions. The system depicted in FIG. 3c does not lessen this operating window significantly, but it does not allow for an easy installation of a RCD. All of these limitations are eliminated by the present invention.
The systems mentioned earlier in U.S. Pat. Nos. 6,904,981 and 7,044,237 discuss closing the choke on a pressurized drilling system, and using manipulation of the choke to control the backpressure of the system, in order to control the pressure at the bottom of the well. This method works in principle, but in field applications of these systems, when drilling in a closed system, the manipulation of the choke can cause pressure spikes that are detrimental to the purpose of these inventions, i.e., precise control of the bottom hole pressure. Also, the peculiarity of a floating drilling installation is, that when a connection is made, the top of the pipe is held stationary in the rotary table (RT in FIG. 1 and FIG. 2). This means that the whole string of pipe in the wellbore now moves up and down as the wave action (known as heave in the industry) causes the pressure effects of surge (pressure increase as the pipe moves into the hole) and swab (pressure drop as the pipe moves out of the hole). This effect already causes substantial pressure variations in the conventional method of FIG. 3a. When the system is closed by the addition of a RCD as shown in FIG. 3d, this effect is even more pronounced by the effect of volume changes by the pipe moving in and out of a fixed volume. As the movement of a pressure wave in a compressed liquid is the speed of sound in that liquid, it implies that the choke system would have to be able to respond at the same or even faster speed. While the electronic sensor and control systems are able to achieve this, the mechanical manipulation of the choke system is very far from these speeds. In order to reduce, or even optimally remove these pressure spikes (negative or positive from the desired baseline), a damping system is required. The best damping system in an incompressible fluid system is the introduction of a compressible fluid in direct contact with the incompressible fluid. This could be a gas, e.g., Nitrogen.
The RCD (Rotating Control Devices) development originated from land operations where typically the installation was on top of the BOP (Blow Out Preventer). This meant that usually there was no further equipment installed above the RCD. As access was easy, almost all of the current designs have hydraulic connections for lubricating and cooling the bearing or for other utilities. These require the attachment of hoses for operation. Although some versions have progressed from surface type to being adapted for use on the bottom of the sea as described in U.S. Pat. No. 6,470,975 they fail to disclose a complete system for achieving this. Some systems as described in U.S. Pat. No. 7,080,685 disperse with hydraulic cooling and lubrication, but require a hydraulic connection to release the assembly. A complete system would require a latching mechanism; that also allows transfer of the hydraulic connections from the outside of the riser to the inside of the riser, and vice versa, so as to remove any hydraulic action or hoses internal to the riser. Furthermore the range of RCDs and possibilities available means that it requires a custom made unit to house a particular RCD design as described U.S. Pat. No. 7,080,685. The U.S. Pat. No. 7,080,685 provides only for a partial removal of the RCD assembly, leaving the body on location.
Many ideas and patents have been filed, but the field application of technology to solve some of the shortcomings in the conventional set-up of FIG. 3a has been limited. All of them modify the existing system in a custom manner taking away some of the flexibility. There exists a gap in the present industry to provide a solution to allow running a pressurized riser for the majority of floating drilling installations to allow closed system drilling techniques, especially Managed Pressure Drilling to be safely and expediently applied without any major modification to the floating drilling installation.
These requirements are:                (1) Be able to pressurize the marine riser to the maximum pressure capacity of its members;        (2) Be able to be safely installed using normal operational practices and operated as part of marine riser without any floating drilling installation modifications as required for surface BOP operations or some subsea ideas;        (3) Provide full-bore capability like a normal marine riser section when required;        (4) Provide the ability to use the standard operating procedures when not in pressurized mode;        (5) Does not lessen the weather (wind, current and wave) operating window of the floating drilling installation;        (6) Provide a means for damping the pressure spikes caused by heave resulting in surge and swab fluctuations;        (7) Provide a means for eliminating the pressure spikes caused by movement of the rotatable tubulars into and out of a closed system; and        (8) Provide a means for easily modifying the density of fluid in the riser at any desired point.        